Method of obtaining improved geophysical information about earth formations

ABSTRACT

The present invention provides a method for forming wellbores. In one method, one or more wellbores are drilled along preplanned paths based in part upon seismic surveys performed from the surface. An acoustic transmitter conveyed in such wellbores transmits acoustic signals at a one or more frequencies within a range of frequencies at a plurality of spaced locations. A plurality of substantially serially spaced receivers in the wellbores and/or at s receive signals reflected by the subsurface formations. The sensors may be permanently installed in the boreholes and could be fiber optic devices. The receiver signals are processed by conventional geophysical processing methods to obtain information about the subsurface formations. This information is utilized to update any prior seismographs to obtain higher resolution seismographs. The improved seismographs are then used to determine the profiles of the production wellbores to be drilled. Borehole seismic imaging may then be used to further improve the seismographs and to plan future wellbores. Cross-well tomography may be utilized to further update the seismographs to manage the reservoirs. The permanently installed sensors may also be used to monitor the progress of fracturing in nearby wells and thereby provide the necessary information for controlling fracturing operations.

CROSS REFERENCE TO RELATED APPLICATIONS

This application is a Divisional application from U.S. patentapplication Ser. No. 09/532,466 filed on Mar. 22, 2000, which is aDivisional application from U.S. patent application Ser. No. 08/948,150filed on Oct. 9, 1997 (now U.S. Pat. No. 6,065,538) which iscontinuation in part of U.S. patent application No. 08/856,656 filed onMay 15, 1997, now U.S. Pat. No. 6,006,832 which is a continuation inpart of patent application Ser. No. 08/695,450 filed on Aug. 12, 1996(now U.S. Pat. No. 5,662,165, issued Sep. 2, 1997) which is a divisionalof patent application Ser. No. 08/526,827 filed on Sep. 11, 1995 (nowU.S. Pat. No. 5,730,219) which is a continuation in part of patentapplication Ser. No. 08/386,480 filed Feb. 9, 1995 (now U.S. Pat. No.5,597,042). The patent application Ser. No. 08/948,150 (now U.S. Pat.No. 6,065,538) claimed a priority date of Oct. 9, 1996, based onProvisional Application Ser. No. 60/027,860, filed on Oct. 9, 1996 and apriority date of May 2, 1997 based on Provisional Application Ser. No.60/045,354.

FIELD OF THE INVENTION

This invention relates generally to the placement of wellbores andmanagement of the corresponding reservoirs and more particularly toselectively drilling one or more wellbores for conducting seismicsurveys therefrom to improve the seismographs and utilizing the improvedseismographs to determine the type and course of wellbores fordeveloping a field. The method of the present invention further relatesto obtaining seismic information during drilling of the wellbores andduring production of hydrocarbons for improving hydrocarbon productionfrom the reservoirs. The method of the present invention further relatesto using the derived seismic information for automatically controllingpetroleum production wells downhole computerized control systems.

BACKGROUND OF THE INVENTION

Seismic surveys are performed from surface locations to obtain maps ofthe structure of subsurface formations. These surveys are in the form ofmaps (referred herein as seismographs”) depicting cross-section of theearth below the surveyed region or area. Three dimensional (“3D”)surveys have become common over the last decade and providesignificantly better information of the subsurface formations comparedto the previously available two-dimension (“2D”) survey. The 3D surveyshave significantly reduced the number of dry wellbores. Still, sincesuch seismic surveys are performed from the surface, they loseresolution due to the distance between the surface and the desiredhydrocarbon-bearing formations, dips in and around the subsurfaceformations, bed boundary delineations, which is typically severalthousand feet.

Surface seismic surveys utilize relatively low frequency acousticsignals to perform such surveys because such signals penetrate togreater depths. However, low frequency signals provide lower resolution,which provides low resolution seismographs. High frequency signalsprovide relatively high resolution boundary delineations, but attenuaterelatively quickly and are, thus, not used for performing seismicsurveys from the surface.

Only rarely would an oil company drill a wellbore without first studyingthe seismographs for the area. The number of wellbores and the path ofeach wellbore is typically planned based on the seismographs of thearea. Due to the relatively low resolution of such seismographs,wellbores are frequently not drilled along the most effective wellpaths. It is therefore desirable to obtain improved seismographs priorto drilling production wellbores. Additionally, more and more complexwellbores are now being drilled, the placement of which can be improvedwith high definition seismographs. Furthermore, relatively recently, ithas been proposed to drill wellbores along contoured paths throughand/or around subsurface formations to increase potential recovery or toimprove production rates of hydrocarbons. In such cases, it is even morecritical to have seismographs that relatively accurately depict thedelineation of subsurface formations.

Conventionally, seismographs have been updated by (a) performingborehole imaging, which is typically conducted while drilling a wellboreand (b) by cross-well tomography, which is conducted while between anumber of producing wells in a region. In the case of borehole imaging,a seismic source seismic source generates acoustic signals duringdrilling of the wellbore. A number of receivers placed on the surfacereceive acoustic reflections from subsurface formation boundaries, whichsignals are processed to obtain more accurate bed boundary informationabout the borehole. This technique helps improve the surfaceseismographs in piecemeal basis. Data from each such well being drilledis utilized to continually update the seismographs. However, suchwellbores are neither planned nor optimally placed for the purpose ofconducting subsurface seismic surveys. Their well paths and sizes aredetermined based upon potential recovery of hydrocarbons. In the case ofcross-well tomography, acoustic signals are transmitted between varioustransmitters and receivers placed in producing wellbores. Theeffectiveness of such techniques are reduced if the wellbores are notoptimally placed in the field. Such techniques would benefit fromwellbores which are planned based on improved seismographs.

In the control of producing reservoirs, it would be useful to haveinformation about the condition of the reservoir away from the borehole.Crosswell techniques are available to give this kind of information. Inseismic tomography, a series of 3-D images of the reservoir is developedto give a 4-D model or the reservoir. Such data has usually beenobtained using wireline methods in which seismic sensors are loweredinto a borehole devoted solely for monitoring purposes. To use such dataon a large scale would require a large number of wells devoted solely tomonitoring purposes. Furthermore, seismic data acquired in differentwireline runs commonly suffers from a data mismatch problem where, dueto differences in the coupling of the sensors to the formation, data donot match.

The present invention addresses the above-noted problems and provides amethod of conducting subsurface seismic surveys from one or morewellbores. These wellbores may be drilled for the purpose of conductingsuch surveys. Alternatively, permanently implanted sensors in a boreholethat could even be a production well could be used to gather such data.The data from such subsurface surveys is utilized to improve thepreviously available seismographs. The improved seismographs are thenutilized to plan the production wellbores. Borehole seismic imaging andcross-well tomography can be utilized to further improve theseismographs for reservoir management and control.

SUMMARY OF THE INVENTION

The present invention provides a method for forming wellbores. In onemethod, one or more wellbores are drilled along preplanned paths basedin part upon seismic surveys performed from the surface. An acoustictransmitter transmits acoustic signals at one or more frequencies withina range of frequencies at a plurality of spaced locations. A pluralityof substantially serially-spaced receivers in the wellbores and/or atsurface receive signals reflected by the subsurface formations. Whilethe acoustic receivers are permanently deployed downhole, the acoustictransmitter may optionally be positioned permanently or temporarilydownhole; or may be positioned permanently or temporarily at the surfaceof the well The receiver signals are processed by conventionalgeophysical processing methods to obtain information about thesubsurface formations. This information is utilized to update any priorseismographs to obtain higher resolution seismographs. The improvedseismographs are then used to determine the profiles of the productionwellbores to be drilled. Borehole seismic imaging may then be used tofurther improve the seismographs and to plan future wellbores.Information gathered from tomographic surveys carried out over a periodof time can be used to map changes in the reservoir conditions away fromthe boreholes and appropriate control measures may be taken. Fiber opticsensors, along with a light source, can also be used to detect theacoustic and seismic signals.

Another embodiment of the present invention includes permanent downholeformation evaluation sensors which remain downhole throughout productionoperations. These formation evaluation sensors for formationmeasurements may include, for example, gamma ray detection lairformation evaluation, neutron porosity, resistivity, acoustic sensorsand pulse neutron which can, in real time, sense and evaluate formationparameters including important information regarding water migratingfrom different zones. Permanently installed fiber optic sensors can alsobe used to measure acoustic signals, pressure, temperature and fluidflow. These are utilized to in the seismic mapping as well as inobtaining and updating reservoir models and in managing the productionof hydrocarbons.

On particularly advantageous permanent downhole sensor installationinvolves the permanent placement of acoustic transmitters and receiversdownhole in oil, gas or injection wells for collecting real time seismicdata This seismic data is used for, among other purposes, (a) definingthe reservoir, (b) defining distribution of oil, water and gas in areservoir with respect to time; (c) monitoring the saturation, depletionand movement of oil water and gas; and (d) monitoring the progress of afracturing operation. In contrast to prior art seismic monitoring, thedata obtained by the present invention is real time.

BRIEF DESCRIPTION OF THE DRAWINGS

For detailed understanding of the present invention, references shouldbe made to the following detailed description of the preferredembodiment, taken in conjunction with the accompanying drawings, inwhich like elements have been given like numerals, wherein:

FIG. 1 shows a schematic illustration of the placement of a wellbore andcorresponding transmitters and receivers for conducting subsurfaceseismic surveys according to an embodiment of the present invention.

FIG. 1a shows a receiver grid for use at the surface according to anembodiment of the present invention.

FIG. 2 shows a schematic illustration of the placement of a plurality ofwellbores and corresponding transmitter and receivers for conductingsubsurface seismic survey according to an embodiment of the presentinvention.

FIG. 3 shows a schematic illustration of multiple production wellboresformed for producing hydrocarbons utilizing the information obtainedfrom surveys performed according to the present invention.

FIG. 4 shows a schematic illustration of multiple production wellboresformed for producing hydrocarbons utilizing the information obtainedfrom surveys performed according to the present invention, wherein atleast one of the production wellbores is formed from the wellbore formedfor performing subsurface seismic survey.

FIG. 5 is a diagrammatic view of an acoustic seismic monitoring systemin accordance with the present invention.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

In general, the present invention provides methods for obtainingimproved seismic models prior to drilling production wellbores, drillingwellbores based at least partially on the improved seismic models andmethod for improving reservoir modeling by continued seismic surveyduring the life of the production wellbores.

FIG. 1 shows a schematic illustration of an example of the placement ofa survey wellbore and receivers and the source points for conductingsubsurface seismic surveys according to the present invention. For thepurposes of illustration and ease of understanding the methods of thepresent invention are described by way of examples and, thus, suchexamples shall not be construed as limitations. Further, the methods aredescribed in reference to drilling wellbores offshore but are equallyapplicable to drilling of wellbores from onshore locations. In thisconfiguration, a survey wellbore 10 is planned based on any preexistinginformation about the subsurface formation structure. Such informationtypically includes seismic surveys performed at the surface and mayinclude information from wellbores previously formed in the same ornearby fields. As an example, FIG. 1 shows non-hydrocarbon bearingformations Ia and Ib separated by hydrocarbon bearing formations IIa andIIb (also referred to herein as the “production zones” or “reservoirs”).After the wellpath for the survey wellbore 10 has been determined, it isdrilled by any conventional manner. Typically, reservoirs are foundseveral thousand feet deep from the earth's surface and in manyinstances oil and gas is trapped in multiple zones separated bynon-hydrocarbon bearing zones. It is preferred that the hydrocarbonbearing formations be not invaded by drilling fluids and other drillingactivity except as may be necessary to drill wellbores for recoveringhydrocarbons from such formations. Therefore, it is generally preferredthat the survey wellbore 10 be placed in a non-hydrocarbon bearingformation, such as formation Ia. Additionally, it is preferred that thesurvey wellbore be placed relatively close to and along the reservoirs.

Typically, production wellbores are relatively large in diameter,generally greater than seven inches (7″) in diameter. Such largediameter wellbores are expensive to drill. Survey wellbores, such asexemplary wellbore 10, however, need only be large enough to accommodateacoustic receivers, such as hydrophones, fiber optic sensors, and anacoustic source moved within the wellbore as more fully explained later.Such small diameter wellbores can be drilled relatively inexpensively innon-producing zones without concerning invading formations near theborehole. Additionally, relatively inexpensive fluids may be utilized todrill such wellbores. As noted earlier, reservoirs typically lie severalthousand feet below the earth's surface and thus the survey wellbore,such as wellbore 10, may be placed several thousand feet below theearth's surface. Additionally, if the survey wellbore is not eventuallygoing to be utilized for purposes that would require casing or otherwisecompleting the wellbore, such wellbore may be filled with a heavy fluid(called the “kill-weight” fluid) to prevent collapse of the wellbore.

Once the survey wellbore 10 has been drilled, a receiver string or line12 with a plurality of serially spaced receivers 12 a is placed alongthe wellbore. The receiver locations 12 a are preferably equi-spaced andeach receiver location 12 a may include one or more receivers, such ashydrophones, seismometers or accelerometers. The receivers could also besingle or a plurality of fiber optic strings or segment, each suchsegment containing a plurality of spaced apart fiber optic sensors: insuch a case, a light source and detector (not shown) are disposed usedin the wellbore to transmit light energy to the sensors and receiver thereflected light energy from the sensors and a suitably placed dataacquisition and processing unit is used for processing the lightsignals. The use of such receiver lines is known in the art and is notdescribed in detail herein. Alternatively or in addition to the receiverstring 12, one or more receiver lines, such as lines 14, each having aplurality of serially spaced acoustic sensors 14 a may be placed on theocean bottom 16 for relatively shallow water applications. Forrelatively deep water applications, one or more receiver lines may beplaced a relatively short distance below the water surface 22. Receiverlines 22 are made buoyant so that they remain at a desired distancebelow the water surface. FIG. 1a shows a plan view of an exemplaryconfiguration of a plurality of receiver lines R1-Rn that may be placedon the earth's surface. The receivers in each line designated by r_(ij),where i represents the line and j represents the sequential position inthe line i. The receivers in adjacent lines are shown staggered one halfthe distance between adjacent receivers.

The same fiber-optic sensor could be used as an acoustic sensor and todetermine other downhole conditions, such as the temperature, pressureand fluid flow. The use of fiber optic sensors in downhole tools isfully described in Provisional Application Ser. No. 60/045,354,incorporated herein by reference.

Referring back to FIG. 1, to perform a seismic survey from the surveywellbore 10, a seismic source (acoustic transmitter) is energized at afirst location, such as location 12 s ₁. The acoustic signals travelaround the survey wellbore 10 and are reflected and refracted by the bedboundaries between the various formations. The reflected waves, such aswaves 30 are detected by the receivers 12 s in the survey wellbore 12.The detected signals are transmitted to a surface control unit 70, whichprocesses the detected signals according to known seismic processingmethods. Desired information relating to the survey activity isdisplayed on the display and any desired information is recorded by therecorder. The control unit preferably includes a computer with a seismicdata processing programs for performing processing receiver data and forcontrolling the operation of the source 15.

The source 15 is then moved to the next location in the wellbore 10 andthe above process is repeated. When receiver lines, such as lines 14 aredeployed on the sea bottom 16, then the signals 32 reflected from thesubsurface formations are detected by the receivers 14 a. The signalsdetected by the sensors 14 a are then collected and processed by thecontrol unit 70 in the manner described earlier. When receiver lines 18are suspended in the ocean water 20 then reflected signals as shown bylines 34 are detected by the receivers 18 a in lines 18. The signalsreceived by the lines 18 are then processed by the control unit 70 inthe manner described earlier. It should be noted that for the purpose ofthis embodiment of the invention any combination of the receiver linesmay be utilized. Additionally, the source may be activated at surfacelocations.

In the first embodiment of the invention, the source 15 is preferablyconveyed into the survey wellbores 10 and moved to each of the sourcepoints 15 s ₁. This allows utilizing only one source for performing thesurvey. The source 15 preferably is adapted to transmit acoustic signalsat any frequency within a range of frequencies. The control unit 70 isused to alter the amplitude and frequency of the acoustic signalstransmitted by the source 15. Since the survey wellbore is strategicallyplaced from relatively short distance from some or all of the producingformations, a relatively high frequency signals may be utilized toobtain high resolution seismic maps for short distances, which is norfeasible from any seismic surveys performed from the surface.Additionally, the source 15 may be oriented in any direction to transmitacoustic signals in a particular direction (herein referred to as thefocused signals). This can allow obtaining true three dimensional bedboundary information respecting formations surrounding the surveywellbore 10. During drilling of the wellbore, core cuttings from knowndepths provide information about the rock structure, which in turn canbe used to determine relatively accurately the acoustic velocities ofsome of the formations surrounding the survey wellbore 10. Thesevelocities are utilized in processing the signals detected by thereceiver lines, such as lines, such as line 12, 14 and 18. This providesmore accurate delineation of bed boundaries compared to surface seismicsurveys which typically use estimated values of acoustic velocities forsubsurface formations.

The information obtained from the survey as described above is used toupdate preexisting seismic models. This may be done by combining thedata obtained from the survey performed from the survey wellbore 10 orby any other known method. Additionally actual acoustic velocities ofthe subsurface formations obtained herein can be utilized to update theseismic models of the area.

Now referring to FIG. 1a, the source line defined by s₁-s_(p) is shownto be symmetrically placed in relation to the surface seismic linesR₁-R_(n). It is preferred to utilize symmetrical receiver andtransmitter configurations because it simplifies processing of data.

FIG. 2 shows a schematic illustration of the placement of a plurality ofwellbores and corresponding transmitter and receiver lines forconducting subsurface seismic'survey according to one method of oneembodiment of the invention. In this configuration, a survey wellbore100 is formed along a wellpath based on the prior seismic and othersubsurface formation information available. The wellbore 100 has a firstbranch wellbore 100 a placed above the firs reservoir IIa and a secondbranch wellbore 100 b placed above and along a second reservoir IIb.Other configurations for multiple survey wellbores may be adopted basedupon the location of reservoirs to be developed. For example, separatewellbores may be drilled from different surface locations. A surveywellbore may be drilled along a dip to more precisely map the dippingformation utilizing relatively high frequency acoustic signals.

Each of the survey wellbores, such as wellbores 100 a and 100 b arelined with a receiver line 102 and 104 respectively. To conduct seismicsurvey from wellbore 100 a, a transmitter is activated from each of thesource points s. The reflected signals 106 are detected by the receiversr in the line 102, receivers in any other survey wellbore and by anyother receivers placed on the surface. The data from the receivers isthen processed by the control unit in the manner described earlier withrespect to FIG. 1 to obtain information about the subsurface formations.Seismic data may be obtained at different frequencies and by utilizingfocused signals in the manner described earlier with respect to FIG. 1.

FIG. 3 shows a schematic illustration of multiple production wellboresformed for producing hydrocarbons utilizing the information obtainedfrom surveys performed according to one embodiment of the invention.Once the subsurface geological information has been updated, the sizeand the placement of production wellbores, such as wellbores 100, 100 aand 100 b for developing a region are determined based upon the updatedseismographs or subsurface models. The desired production wellbores aredrilled and completed to produce hydrocarbons. It is desirable to placea plurality of receivers, such as receivers 202 in wellbore 200 a andreceivers 206 in wellbore 200 b. In some cases it may be desirable toleave the receiver line 12 in the survey wellbore 10. During the life ofthe wellbores 200 a and 200 b, acoustic sources may be activated atselective locations in any of the production wellbores and in the surveywellbore 10. The receivers in the various wellbores detect signalscorresponding to the transmitted signals. The detected signals are thenprocessed to determine the condition of the various reservoirs overtime. This information is then used to update reservoir models. Theupdated reservoir models are subsequently utilized to manage productionfrom the various wellbores in the field. The updated models may be usedto selectively alter production rates from any of the productionwellbores in the field, to shut in a particular well, to workover aparticular production wellbore, etc. The permanent availability ofreceiver lines in the survey wellbore 10, relatively close to theproduction wellbores 200 a and 200 b, provides more accurate informationabout the subsurface formations than surveys conducted from the surface.However, surface seismic surveys, if performed after the wellbores havebeen producing, may still be updated with information obtained fromsurveys performed using survey wellbore 10.

FIG. 4 shows a schematic illustration of multiple production wellboresformed for producing hydrocarbons utilizing the information obtainedfrom surveys performed according to one embodiment of the invention,wherein at least one of the production wellbores is formed from thewellbore formed for performing subsurface seismic survey. In some casesit may be desirable to drill a survey wellbore which can later beutilized to form production branch wellbores therefrom. FIG. 4 shows theformation of a survey wellbore 300 a from a common vertical well section300. The wellbore 300 is first used to perform seismic surveys in themanner described herein and then one or more production wellbores, suchas wellbores 300 b and 300 c, are formed from the survey wellbore 300 a.Additional production wellbores, such as wellbore 310 may be formed fromthe common wellbore section 300 or from other surface locations (notshown) as desired. Receivers 302 a and 312 a respectively shown in thewellbores 300 a and 310 perform the same functions as explained earlierwith respect to FIGS. 1-3.

Another aspect of the invention is the use of permanently installeddownhole acoustic sensors. FIG. 5 depicts a schematic representation ofthe acoustic seismic monitoring system as described immediately above.FIG. 5 more particularly depicts a production well 410 for producingoil, gas or the like. Well 410 is defined by well casing 412 which iscemented or otherwise permanently positioned in earth 414 using anappropriate cement 416. Well 410 has been completed in a known mannerusing production tubing with an upper section of production tubing beingshown at 416A and a lower section of production tubing being shown at416B. Attached between production tubing 416A and 416B, at anappropriate location, is the permanent acoustic seismic sensor inaccordance with the present invention which is shown generally at 418.Acoustic seismic sensor 418 comprises a housing 420 having a primaryflow passageway 422 which communicates with and is generally inalignment with production tubing 416A and 416B. Housing 420 alsoincludes a side passageway 424 which is laterally displaced from primaryflow passageway 422. Side passageway 424 is defined by a laterallyextending section 426 of housing 420 and an interior dividing wall 428.Positioned within side passageway 424 is a downhole electronics andcontrol module 430 which is connected in series to a plurality ofpermanent acoustic receivers 432 (e.g., hydrophones, seismometers andaccelerometers). The acoustic receivers 432 are placed longitudinallyalong production tubing 416 (and therefore longitudinally along the wallof the borehole) in a region of the geological formation which is ofinterest in terms of sensing and recording seismic changes with respectto time. At the surface 434 is a surface control system 436 whichcontrols an acoustic transmitter 438. As discussed, transmitter 438 mayalso be located beneath the surface 434. Transmitter 438 willperiodically transmit acoustic signals into the geological formationwhich are then sensed by the array of acoustic receivers 432 with theresultant sensed data being processed using known analysis techniques.

A more complete description of wellbores containing permanent downholeformation evaluation sensors can be found in U.S. Pat. No. 5,662,165 allof the contents of which are incorporated herein by reference.

As discussed in trade journals such as in the articles entitled “4DSeismic Helps Track Drainage, Pressure Compartmentalization,” Oil andGas Journal, Mar. 27, 1995, pp 55-58, and “Method Described for Using 4DSeismic to Track Reservoir Fluid Movement,” Oil and Gas Journal, Apr. 3,1995, pp. 70-74 (both articles being filly incorporated herein byreference), seismic monitoring of wells over time is becoming animportant tool in zing and predicting well production and performance.Prior to the present invention, such seismic monitoring could only bedone in near real time using known wire-line techniques; or on sensorsmounted on the outside of tubing of various sorts for shallowapplications (never in producing wells). Examples of such seismicmonitoring are described in U.S. Pat. No. 5,194,590; the article“Tie-lapse crosswell seismic tomogram Interpretation: Implications forheavy oil reservoir characterization, thermal recovery processmonitoring and tomographic imaging technology” Geophysics v. 60, No. 3,(May-June), p 631-650; and the article “Crosswell seismic radial surveytomograms and the 3-D interpretation of a heavy oil steamflood.”Geophysics v. 60, no. 3, (May-June) p 651-659 all of the contents ofwhich are incorporated herein by reference. However, in accordance withthe present invention, a significant advance in seismic monitoring isaccomplished by installing the seismic (e.g., acoustic) sensors as apermanent downhole installation in a well. A plurality of seismictransmitters, as described in U.S. Pat. No. 5,662,165 are used assources of seismic energy at boreholes at known locations. The seismicwaves detected at receivers in other boreholes, upon proper analysis,provide a detailed three dimensional picture of a formation and fluidsin the formation with respect to time. Thus, in accordance with thisinvention, a well operator has a continuous real time three dimensionalimage of the borehole and surrounding formation and is able to comparethat real time image with prior images to ascertain changes in theformation; and as discussed in detail above, this constant monitoringcan be done from a remote location.

Such an imaging of fluid conditions is used to control productionoperations in the reservoir. For example, an image of the gas-watercontact in a producing gas reservoir makes it possible to take remedialaction before water is produced in a well by selectively closingsleeves, packers, safety valves, plugs and any other fluid controldevice downhole where it is feared that water might be produced withoutremedial action. In a steam-flood or CO₂ flood operation for secondaryrecovery of hydrocarbons, steam or CO₂ are injected into the reservoirat selected injection wells. The steam or CO₂ drive the oil in the porespaces of the reservoir towards the producing wells. In secondaryrecovery operations, it is critical that the steam or CO₂ not enter theproducing wells: if a direct flow path for steam or CO₂ is establishedbetween the injection well and the recovery well (called abreakthrough), further “flushing” operations to recover oil areineffective. Monitoring of the position of the steam/oil or CO₂/oilinterface is therefore important and by closing sleeves, packers, safetyvalves, plugs and any other fluid control device in a producing wellwhere breakthrough is imminent, the flow patterns can be alteredsufficiently to avoid a breakthrough. In addition, sleeves and fluidpressure control devices can be operated in the injection wells toaffect the overall flow of fluids in the reservoir. The downhole seismicdata for performing the tomographic analysis is transmitted uphole usingmethods described in U.S. Pat. No. 5,662,165, gathered by the controlcenter and transmitted to a remote site where a powerful digitalcomputer is used to perform the tomographic analysis in accordance withmethods described in the patent and references above.

Another aspect of the invention is the ability to control a fracturingoperation. In a “frac job”, fluid at a high pressure is injected into ageologic formation that lacks adequate permeability for the flow ofhydrocarbons. The injection of high pressure fluid into a formation at awell has the effect of fracturing the formation. These fracturesgenerally propagate away from the well in directions determined by theproperties of the rock and the underground stress conditions. Asdiscussed by P. B. Wills et al in an article entitled “Active andPassive Imaging of Hydraulic fractures” Geophysics, the Leading Edge ofExploration, July, p 15-22, (incorporated herein by reference), the useof downhole geophones in one well (a monitor well) makes it possible tomonitor the propagation of fractures from another well in whichfracturing is being induced. The propagating fracture in the formationacts as a series of small seismic sources that emit seismic waves. Thesewaves can be recorded in the sensors in the monitor well and based uponthe recorded signals in a number of monitor wells, the active edge ofthe fracture can be mapped. Having such real-time observations makes itpossible to control the fracturing operation itself using the methods ofthis invention.

While the foregoing disclosure is directed to the preferred embodimentsof the invention various modifications will be apparent to those skilledin the art. It is intended that all variations within the scope andspirit of the appended claims be embraced by the foregoing disclosure.Examples of the more important features of the invention have beensummarized rather broadly in order that the detailed descriptionunderstood, and in order that the contributions to the art may beappreciated. There are, of course, additional features of the inventionthat will be described hereinafter and which will form the subject ofthe claims appended hereto.

What is claimed is:
 1. A method of obtaining geophysical informationabout subsurface formations, comprising: (a) permanently deploying aplurality of fiber optic sensors in a survey wellbore, each said sensorhaving a fiber optic element detecting a seismic wave; (b) using saidfiber optic sensors for detecting seismic waves traveling through thesubsurface formations; and (c) processing the detected seismic waves toobtain geophysical information about the subsurface formation.
 2. Themethod of claim 1 wherein the processing is performed at the surface ordownhole.
 3. The method of claim 1 further comprising deploying a sourceof light downhole, said source providing light energy to the fiber opticsensors.
 4. The method of claim 1 wherein the fiber optic sensors aredistributed along the wellbore.
 5. The method of claim 1, wherein thesurvey wellbore is formed so as to not intersect a hydrocarbon bearingformation.
 6. The method of claim 1 further comprising combining theobtained geophysical information about the subsurface formations withother data to obtain enhanced geophysical information about the earth'ssubsurface formations.
 7. The method of claim 1 further comprisingforming a production wellbore in the earth formation utilizing theobtained geophysical information.
 8. The method of claim 6, wherein theenhanced geophysical information is one of (i) a seismograph of theearth's subsurface formations, (ii) an acoustic velocity of a subsurfaceformation, (iii) distance between the survey wellbore and a bedboundary, and (iv) distance between at least two subsurface bedboundaries.
 9. The method of claim 8, wherein the seismograph is a 4-Dmap of the subsurface formations.
 10. The method of claim 1, wherein theseismic waves are generated by a source placed at a location that is oneof (i) within the survey wellbore, (ii) at the surface, (iii) anoffshore location, (iv) a secondary wellbore, and, (v) a productionwellbore.
 11. The method of claim 1 further comprising: (i) placing asecond plurality of spaced seismic receivers outside the surveywellbore; (ii) detecting said seismic waves in the second plurality ofreceivers and generating signals responsive to such detected seismicwaves; and (iii) combining the signals from the first and secondpluralities of receivers to obtain the geophysical information.
 12. Themethod of claim 11 wherein said second plurality of spaced seismicreceivers comprises fiber optic sensors.
 13. The method of claim 1further comprising: (i) subsequently conducting seismic surveys toobtain secondary information about the subsurface formation, and (ii)combining the obtained geophysical information and the secondarygeophysical information to obtain an enhanced map of the subsurfaceformations.
 14. The method of claim 1 further comprising producing across-well seismograph from the detected seismic waves.
 15. The methodof claim 1 wherein said survey wellbore follows a predetermined wellpathas a sidebore from a production wellbore.
 16. A method of obtaininggeophysical information about subsurface formations, comprising: (a)deploying a plurality of fiber optic sensors in a first survey wellbore,each said sensor having a fiber optic element for detecting a seismicwave; (b) generating seismic waves in the subsurface using at least onetransmitter in a second survey wellbore and using said fiber opticsensors for detecting said generated seismic waves traveling through thesubsurface formations; and (c) processing the detected seismic waves toobtain geophysical information about the subsurface formation.
 17. Themethod of claim 16 wherein the processing is performed at the surface ordownhole.
 18. The method of claim 16 further comprising deploying asource of light for providing light energy to the fiber optic sensors.19. The method of claim 16 wherein the fiber optic sensors aredistributed along the wellbore.
 20. The method of claim 16, wherein thesurvey wellbore is formed so as to not intersect a hydrocarbon bearingformation.
 21. The method of claim 16 further comprising combining theobtained geophysical information about the subsurface formations withother data to obtain enhanced geophysical information about the earth'ssubsurface formations.
 22. The method of claim 16 further comprisingforming a production wellbore in the earth formation utilizing theobtained geophysical information.
 23. The method of claim 21, whereinthe enhanced geophysical information is one of (i) a seismograph of theearth's subsurface formations, (ii) an acoustic velocity of a subsurfaceformation, (iii) distance between the survey wellbore and a bedboundary, and (iv) distance between at least two subsurface bedboundaries.
 24. The method of claim 23, wherein the seismograph is a 4-Dmap of the subsurface formations.
 25. The method of claim 16 furthercomprising: (i) using a second plurality of spaced seismic receiversoutside the first survey wellbore for detecting said seismic wavesreflected by earth's formations and generating signals responsive tosuch detected seismic waves; and (iii) combining the signals from thefiber optic sensors and the seismic receivers to obtain the geophysicalinformation.
 26. The method of claim 25 wherein said second plurality ofspaced seismic receivers comprises fiber optic sensors.
 27. The methodof claim 16 further comprising: (i) subsequently conducting seismicsurveys to obtain secondary information about the subsurface formation,and (ii) combining the obtained geophysical information and thesecondary geophysical information to obtain an enhanced map of thesubsurface formations.
 28. The method of claim 16 further comprisingproducing a cross-well seismograph from the detected seismic waves. 29.The method of claim 16 wherein at least one of said first and secondsurvey wellbores follows a predetermined wellpath as a sidebore from aproduction wellbore.
 30. The method of claim 18 wherein said source oflight is downhole.